1. Field of the Disclosure
Embodiments disclosed herein relate generally to apparatus and methods for downhole drilling operations. More specifically, embodiments disclosed herein relate to a downhole hole mud motor.
2. Background Art
In the drilling of well bores in the oil and gas industry, it is common practice to use downhole motors to drive a drill bit through a formation. As used herein, a “downhole motor” may refer generally to any motor used in a well bore for drilling through a formation. These downhole motors may typically be driven by pumping drilling fluids (e.g., “mud”) from surface equipment downhole through the drill string. As such, this type of motor is commonly referred to as a mud motor. When in use, the drilling fluid may be forced from the surface through the motor portion of the mud motor, in which energy from the flow of the drilling fluid may be used to provide rotational force to a drill bit located below the mud motor. As used herein, a “motor portion” may refer to the portion of the downhole motor that generates torque. There are two primary types of mud motors: positive displacement motors (“PDM”) and turbine motors.
The first type of mud motor, PDM, may be used to convert the energy of high-pressure drilling fluid into rotational-mechanical energy to rotate the drill bit. An early example of a PDM is given in U.S. Pat. No. 4,187,918 (“Clark”). As shown in Clark, a PDM typically has a helical stator attached to a distal end of the drillstring. The PDM may also have an eccentric helical rotor that corresponds to the helical stator and is connected through a driveshaft to the remainder of a bottom hole assembly (“BHA”) therebelow. Drilling fluids may be pressurized to flow through the bore of the drillstring to engage the stator and rotor, thereby creating a resultant torque between the stator and the rotor. This torque may then be transmitted to the drill bit to rotate the drill bit. Historically, PDM's have been characterized as having a low-speed and high-torque when rotating the drill bit. Accordingly, PDM's may generally be best suited for use with roller cone and polycrystalline diamond compact (PDC) bits. However, the rotors of PDM's have been known to have eccentric motion, thereby creating large lateral vibrations that may damage other drill string components.
The second type of mud motor, the turbine motor, generally uses one or more turbine power sections to provide rotational force to a drill bit. Each power section may consist of a non-moving stator vane, and a rotor assembly comprising rotating vanes mechanically linked to a rotor shaft. These power sections are designed such that the vanes of the stator direct the flow of drilling fluid into corresponding rotor blades to provide rotation. The rotor shaft, which may be a single piece, or may comprise two or more connected shafts, such as a flexible shaft and an output shaft, then ultimately connects to and drives the drill bit. Thus, the high-speed drilling fluid flowing into the rotor vanes causes the rotor and the drill bit to rotate with respect to the stator housing. Historically, turbine motors have been characterized as having a high-speed and low-torque, when rotating the drill bit. Furthermore, because of the high speed, and because by design no component of the rotor moves in an eccentric path, the output of a turbine motor is typically smoother than the output of PDM's and considered appropriate for use with PDC bits drilling high compressive strength formations.
Drilling fluid, as used in oilfield applications, is typically pumped downhole through a bore of the drillstring at high pressure. Once downhole, the drilling fluid is pumped through the downhole mud motor, where the fluid is exposed to internal components of the downhole motor, such as bearings and seals. After the drilling fluid has passed through the downhole mud motor, the drilling fluid is then transferred to the drill bit and communicated to the well bore through a plurality of nozzles. Here the drilling fluid cools and lubricates the drill bit, in addition to cleaning drill cuttings away from cutting surfaces of the drill bit and the wellbore. The drilling fluid is then expelled to return to the surface through an annulus formed between the wellbore (i.e., the inner diameter of either the formation or a casing string) and the outer profile of the drillstring. Accordingly, the drilling mud returns to the surface carrying drill cuttings disposed therein. Because the drilling fluid is exposed to the internal components of the downhole motor, the chemical composition and viscosity of the drilling fluid must be carefully considered. The composition and viscosity may have a direct or indirect impact on the internal components of the downhole motor, such as reliability and maintainability.
Both the PDM and the turbine motor, discussed above, require the drilling fluid to be pumped from the surface and circulated through the motor portion of the downhole motor. Thus, the internal components of the PDM and the turbine motor are exposed to the drilling fluid and, therefore, may be affected by the viscosity and the composition of the drilling fluid. This exposure, as described above, may cause the internal components of the PDM and the turbine motor to wear down quickly. Further, this exposure may result in a less reliable and maintainable downhole motor.
Thus, there exists a need for a fluid driven downhole motor that is more reliable and maintainable.